The present disclosure relates to a method of analyzing microseismic data obtained from monitoring induced hydraulic fracturing of underground oilfield geological formations.
Hydraulic fracture monitoring (“HFM”) is employed in underground oil and gas wellbores to provide an understanding of the geometry of placed hydraulic fracturing to enable better completion design, reliable production predictions and real-time operational decisions during the treatment itself.
Hydraulic fracturing involves the injection of a fluid into the surrounding geological formation with the intention of initiating fracture(s). During such fracturing, elastic waves are produced as the material in the path of fracture propagation fails. Such seismic events are captured and are referred to as microseismic events due to the low magnitude of sound typically emitted.
For each microseismic event seismic traces are recorded, which include both the longitudinal and transverse waves travelling through the formation. These traces are recorded at a number of locations, typically using one or more lines of receivers that may be disposed in one or more monitoring wells or at surface. From these traces it is possible to locate the origin of the microseismic event in space and time.
However the measured data can include a large degree of scatter and uncertainty as to the precise spatial location of the microseismic event. Additionally, microseismic data can be measured that is clearly unrelated to the immediate propagation of a fracture, and relates to other geological or mechanical processes, which may or may not be associated with the fracture propagation.
One common source of such microseismic data is plane slippage, typically occurring ahead of the fracture, along a preexisting fracture plane in the formation. The additional stresses caused by hydraulic fracturing can trigger such a fracture plane to slip even ahead of the propagation of a fracture, providing an additional source of microseismic data.
Fortunately, the seismic trace forming the microseismic event contains within it information which can be used to infer the orientation of such a failure plane. In general for a stress-drop event there are 6 degrees of freedom and the microseismic event mechanism is described by a moment tensor, which dictates the far-field radiation pattern of longitudinal and transverse waves recorded in HFM. Consequently, a comparison between the amplitudes of the primary (i.e. longitudinal) and secondary (i.e. transverse) elastic waves can be used to infer the orientation of the failure plane.
However if this is done with real world data from an oil and gas wellbore, error and scatter in the data can be so great as to result in the data being interpreted in a manner which is inconsistent with realistic geomechanical bounds. Clearly therefore, this simplistic approach is not suitable for real world environments where noise and scatter are significant issues.
An alternative method of interpretation of this data has been proposed which involves making assumptions regarding preferred plane slippage angles based on external information. In such a method, the plane slippage angle is estimated from an external source and is not derived from the HFM procedure.
Thus, improvements in the area of analyzing microseismic hydraulic fracture plane slippage events from a real HFM procedure would be highly desirable.